Seawater injection for flooding and pressure maintenance in oil-fields is taking place on a massive scale throughout the world. In some giant oil-fields, the current capacity of seawater injection is well over a million barrels per day (equivalent of 42 million gallons per day). Operations of this magnitude demand a thorough understanding of the process of seawater injection.
For illustrative purposes, Table 1 presents the concentrations of inorganic species in seawater as well as in samples of oil-fields produced waters from the Arabian Gulf areas. Sulfate concentration in seawater from the Arabian Gulf is about 1,000 mg/L higher than sulfate concentration in typical seawater streams (e.g., North Sea, Gulf of Mexico, etc.). If the injection rate of seawater from the Arabian Gulf is a million barrels per day (which is currently taking place in some oil-fields in that area), then the impacted reservoir daily in-take of sulfate is about 572,294 Kg (630 tons), and of extra calcium is about 84,254 Kg (93 tons). Formation waters from the Arabian Gulf oil-fields consistently contain excessive concentrations of calcium (14,000 to 30,000 mg/L) and strontium (500 to 1,100 mg/L) as well as a small concentration of barium. The obvious incompatibility between such formation waters and seawater causes unusual, severe sulfate problems in the forms of sparingly soluble cations.
FIG. 1 depicts possible locations of scale deposits throughout the flow paths of water in oil-gas production facilities. Scale deposits could take place: (1) at the surface water injection facility where incompatible sources of water are mixed prior to injection; (2) in injection wells where the injected water starts to mix with the reservoir formation water; (3) downhole in the reservoir where the injected water displaces reservoir formation water; (4) downhole in the reservoir where the mixed injected water and formation water are about to reach the range of producing wells; (5) downhole in the reservoir where the mixed (injected and formation) waters are within the range of producing wells; (6) at the connection of a branched zone where each branch produces different water; (7) at the manifold of a producing zone where water is produced from different blocks within the same producing zone; (8) at topside facility where produced fluids are mixed from different production zones to separate oil and gas from produced waters, or in pipelines that transport produced fluids to on-shore processing facilities; and (9) at disposal wells where produced water is injected for final disposal.
In oil-fields where seawater is injected, there are two periods that can be distinguished by two main types of scale. The first period is the pre-seawater breakthrough where calcium carbonate scale is predominant due to the loss of carbon dioxide. Sulfate scale in this period is less pronounced. Calcium carbonate scale is not difficult to control by inhibitors or acid dissolvers. The second period is the post-seawater breakthrough where sulfate scale is dominant. Formation of sulfate scale leads to critical operational problems and difficulties, and therefore, substantial capital and operating costs.
In the pre-seawater breakthrough period, some reservoir engineers believe that sulfate scale is not much of a problem. This is attributed, in part, to the fact that in such a period, they may rarely have experienced deposits of sulfate scale. However, sulfate scale deposits start to build up outside the wells, within the oil-bearing formation, where they are invisible. For example, calcium sulfate scale deposit is often difficult to physically detect, or even to predict by scale models in the pre-seawater breakthrough period. Calcium sulfate scale is highly likely to build up within the formation long before it starts depositing precipitates on tubular equipment. When sulfate scale physically starts appearing in a widespread way in tubular equipment, this would indicate that scale build up is very advanced.
Sulfate scale deposits are hard, adherent, almost insoluble in mineral acids or other common solvents, and difficult to remove mechanically. This would cause severe flow restrictions in fluids paths from injection wells to disposal wells (FIG. 1). Scale deposits could also possibly include radium and its isotopes (Naturally Occurring Radioactive Materials or NORM) that tend to co-precipitate with barium or strontium or calcium. Such co-precipitation is attributed to the similarity in ionic radius and coordination among these sparingly soluble alkaline cations. The adherent of NORM to sulfate scale constitutes radioactive hazards. Hydrogen sulfide could also be generated due to the conversion of sulfate in downhole by reducing bacteria. This would lead to reservoir souring, corrosion of both downhole and surface equipment, and possible exposure of workers to a lethal dose of hydrogen sulfide. Treatment of sulfate scale and its associated problems tend to be very expensive, trial-error procedures, field specific, successful only in less severe cases of scaling, and problematic under certain conditions.
However, there is a persistent tendency in oil-gas industries to use available water for injection operations, regardless of the fact that sulfate scale will cause critical problems, and then attempting to remediate such problems that are deliberately allowed to occur. Unfortunately, producers repeatedly fall into the trap of focusing on short-term solutions to their production problems. Production of hydrocarbons under severe conditions such as the continuing injection of seawater without sulfate treatment would doubtlessly create long-term sulfate-related problems.
The only logical effective approach to prevent sulfate scale problems is, unequivocally, the selective removal of sulfate from seawater before injection. This would entirely eliminate the long-term sulfate scale treatment costs (backflow, hydraulic fracturing, acid wash, injection of inhibitors and dissolvers, mechanical reaming, etc.), reduction in productivity index, deferred oil production, and totally prevent the irreversible damages within the invisible oil-bearing formation. New oil-fields seawater injection facilities must include the selective removal of sulfate, and existing facilities that handle only standard seawater pretreatment must be upgraded to include the much-needed sulfate removal treatment.
This patent provides innovative methods to produce nearly sulfate-free seawater for oil-fields water injection operations. That is a proactive, rather than a reactive, approach that could efficiently stimulate producing wells, and economically enhance production in the least damaging manner. Further, the co-production of gypsum as a valuable commodity that can be used in different applications would provide zero or near-zero discharge processing methods.
The innovative methods in this patent are divided into three main processing groups. The first group is based on membrane systems in conjunction with a novel compressed-phase precipitation (CPP) process. The membrane systems in such a group are further divided into pressure-driven membranes (reverse osmosis and nanofiltration), and thermal-driven membranes (membrane distillation and membrane osmotic distillation) in conjunction with the CPP process. The second group is the stand alone CPP process with external seeding mode. The third group is the stand alone CPP process with internal seeding mode.